Hydraulic fracturing is a technology that has evolved into a mature, complex level. The use of hydraulic fracturing is critical to the economical production of hydrocarbons; and is a significant portion of the well-development cost. Despite the progress, it is still not fully understood, and can be interpreted poorly. Although the physical laws governing fracturing are known, the constant emergence of new mechanisms, such as scale-dependent fracture toughness, complex fracturing, dilatancy, and convection, indicates that the basic physics incorporated into models has not been sufficient to model a fracture fully.
The reasons for the uncertainty surrounding the fracturing process are clear. The Earth is a complex, discontinuous medium, and historically there has been limited technology for observing or inferring fracturing results. Nothing can be done about the complexity of typical reservoirs in the Earth, and one can expect that difficulties with complexity will increase as more marginal reservoirs are exploited. On the other hand, diagnostic capabilities continue to improve and technology is reaching the point where fracture diagnostics can be applied by the average producer in problem situations, in new fields, or for validation of new fracturing techniques.
Furthermore, as operators continue to work in difficult, complex lithologies, it becomes clear that stimulation problems cannot be solved without some diagnostic data from which judicious decisions can be made. Diagnostics cost money, but trial-and-error approaches often cost more money and can result in lost wells. Decisions on well spacing, field layout, sand concentrations and volumes, number of zones that can be stimulated in one treatment, optimum perforation schedule, and many other operational parameters can be made correctly if the proper diagnostic information is available in a timely manner.
Recent advances in hydraulic-fracture-mapping technologies have provided good information on the created fracture length in numerous geologic settings. Before having such measurements, fracture length was estimated using fracture-propagation models, but there was significant uncertainty in the results that cascaded into subsequent production analyses. Practitioners also need to understand how the created fracture length relates to the location of proppant in the fracture and to the producing or effective length to evaluate well performance and improve stimulation designs. Unfortunately, most advanced fracture-mapping technologies that provide accurate measurements of the created fracture length have not provided insights into the propped and effective fracture lengths. Advanced production-data analyses (PDAs), pressure-transient testing, and/or numerical reservoir modeling are required to determine the effective fracture length.
The common viewpoint of the far-field hydraulic fracture geometry is changing. Data sets compiled over the last decade are incompatible with the conventional picture of a single, bi-wing, planar hydraulic fracture. These data sets include (1) recovered cores, (2) minebacks, (3) microseismicity, (4) overcores and borehole video, (5) treatment pressure response, and (6) surface tilts, in conjunction with advancements in laboratory simulations, studies of natural hydraulic fracture analogues, and improvements in numerical simulations. The single, planar, farfield fracture viewpoint finds its roots and development in early theory and simplified laboratory studies that were pre-disposed to single, planar fracture geometry. Replacing this viewpoint is a new perspective that includes a strong potential for creating multiple, far-field fractures. The implications of multiple, far-field fracturing has resulted in adjustments to completion and stimulation strategies to address and affect the overall fracture geometry.
One of fracture technology's last frontiers is the understanding and optimization of far-field fracture geometry and proppant placement. Prior to the last decade, the viewpoint of far-field geometry was a single, bi-wing, planar fracture that opened against the least principal stress. But a growing body of data contradicts this viewpoint and a new perspective is emerging. This new viewpoint includes the potential for creating multiple, far-field fractures. As we discuss, the foundation of the new paradigm includes recent field studies, improved laboratory simulations, and advanced theoretical modeling.
In addition knowing the direction or azimuth of the fracture orientation is important in development of a low permeability reservoir with horizontal wellbores. The orientation of the horizontal wellbore will determine if the hydraulic fractures are longitudinal or transverse to the wellbore. The angle of the wellbore to the hydraulic fracture not only affects the recovery factor from the reservoir, but also influences the completion strategy.
Thus practitioners today would like to have much better diagnostics on several hydraulic fracture properties:                Number of hydraulic fractures simultaneously propagating in the far-field        Hydraulic and propped fracture length        Hydraulic fracture azimuth        Multi-planar complex fracture growth        
Artificially created hydraulic fractures are primarily mode-I tensile fractures. Geo-mechanical modeling shows that tensile hydraulic fractures create a characteristic strain distribution in the deformed rock around them. Our modeling shows that strain measurements with sufficient resolution in a properly instrumented monitor well (such as a horizontal well with high resolution distributed strain sensing) can provide information about the approaching hydraulic fractures from an offset stimulation treatment. Approaching hydraulic fractures generate a characteristic strain pattern axially along the monitor wellbore, which can be analyzed to evaluate the above listed fracture properties.
There is a need the to utilize these new capabilities for high resolution distributed strain sensing to develop new diagnostics of hydraulic fracture properties.